Systems for compressing a gas

ABSTRACT

Systems for efficiently compressing a gas are included. In one embodiment, a system includes a carbonous gas compression system and a vapor absorption chiller (VAC). The carbonous gas compression system comprises a compressor configured to compress the carbonous gas. The VAC is configured to circulate a coolant through at least one coolant path through the carbonous gas compression system. Utilization of the VAC may aid in cooling the carbonous gas, which may allow for less energy to be expended by the compression system.

BACKGROUND OF THE INVENTION

The subject matter disclosed herein relates to systems for efficientlycompressing a gas, such as carbon dioxide (CO₂), in a power plant suchas an integrated coal gasification combined cycle (IGCC) or a coal-firedconventional power plant.

Power plants, for example IGCC power plants, may produce a carbonous gassuch as CO₂. In IGCC power plants, a syngas is created by gasifying acarbonaceous fuel such as coal. The syngas may be utilized as fuel forpower generation. The syngas may be fed into a combustor of a gasturbine of the IGCC power plant and ignited to power the gas turbine,which may then drive a load such as an electrical generator. Onebyproduct of such plants may be CO₂. Carbon capture and sequestration isvery likely to be a key element of any future greenhouse gaslegislation, such as CO₂ legislation. Thus, power plants may be underprovisions to separate the CO₂, either pre-combustion or postcombustion. The CO₂ may be captured, compressed, and sequestered.However, the compression of CO₂ requires a considerable amount ofenergy. Accordingly, there is a need for systems that can reduce powerconsumption and overall cost in the compression of CO₂.

BRIEF DESCRIPTION OF THE INVENTION

Certain embodiments commensurate in scope with the originally claimedinvention are summarized below. These embodiments are not intended tolimit the scope of the claimed invention, but rather these embodimentsare intended only to provide a brief summary of possible forms of theinvention. Indeed, the invention may encompass a variety of forms thatmay be similar to or different from the embodiments set forth below.

In a first embodiment, a system includes a carbonous gas compressionsystem and a vapor absorption chiller (VAC). The carbonous gascompression system comprises a compressor configured to compress thecarbonous gas. The VAC is configured to circulate a coolant through atleast one coolant path through the carbonous gas compression system.

In a second embodiment, a system includes a carbonous gas capturesystem, a carbonous gas compression system, a vapor absorption chiller(VAC), and at least a carbon sequestration system or an enhanced oilrecovery (EOR) pipeline. The carbonous gas capture system is configuredto extract the carbonous gas. The carbonous gas compression systemcomprises at least a compressor which is configured to receive thecarbonous gas from the carbonous gas capture system and to compress andliquefy the carbonous gas. The VAC is configured to circulate a coolantthrough at least one coolant path through the carbonous compressionsystem. The carbon sequestration system or the enhanced oil recovery(EOR) pipeline are configured to receive carbonous gas compressed andliquefied by the carbonous gas compression system.

In a third embodiment, a system includes a carbon dioxide (CO₂)compression system, a VAC, and a liquid pump. The CO₂ compression systemcomprises at least a compressor configured to compress the CO₂. The VACis configured to circulate a coolant through at least one coolant paththrough the CO₂ compression system. The liquid pump is configured toraise the pressure of the CO₂.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the presentinvention will become better understood when the following detaileddescription is read with reference to the accompanying drawings in whichlike characters represent like parts throughout the drawings, wherein:

FIG. 1 depicts a block diagram of an embodiment of an integratedgasification combined cycle (IGCC) power plant, including a gascompression system and a vapor absorption chiller system;

FIG. 2 depicts a block diagram of embodiments of the gas compressionsystem and the vapor absorption chiller system depicted in FIG. 1;

FIG. 3 is a depicts a block diagram of an embodiment of a vaporabsorption chiller system; and,

FIG. 4 depicts a block diagram of other embodiments of the gascompression system and the vapor absorption chiller system depicted inFIG. 1.

DETAILED DESCRIPTION OF THE INVENTION

One or more specific embodiments of the present invention will bedescribed below. In an effort to provide a concise description of theseembodiments, all features of an actual implementation may not bedescribed in the specification. It should be appreciated that in thedevelopment of any such actual implementation, as in any engineering ordesign project, numerous implementation-specific decisions must be madeto achieve the developers' specific goals, such as compliance withsystem-related and business-related constraints, which may vary from oneimplementation to another. Moreover, it should be appreciated that sucha development effort might be complex and time consuming, but wouldnevertheless be a routine undertaking of design, fabrication, andmanufacture for those of ordinary skill having the benefit of thisdisclosure.

When introducing elements of various embodiments of the presentinvention, the articles “a,” “an,” “the,” and “said” are intended tomean that there are one or more of the elements. The terms “comprising,”“including,” and “having” are intended to be inclusive and mean thatthere may be additional elements other than the listed elements.

The disclosed embodiments include systems for efficiently compressing acarbonous gas (e.g., CO₂) produced, for example, by extracting CO₂ fromsyngas in the integrated gasification combined cycle (IGCC) system. Thecompression of the carbonous gas allows the gas to be stored, forexample, in a carbon sequestration system or redirected to an enhancedoil recovery (EOR) pipeline. Power plants such as IGCC power plantdescribed in more detail with respect to FIG. 1 below, may gasify a fueland provide for the pre-combustion capture of CO₂ from the fuel.Additionally, the CO₂ may be extracted after the fuel is combusted(i.e., post-combustion extraction), for example, from a flue gas. TheCO₂ may then be transported, and stored or sequestered, for example, ina supercritical state. The supercritical state of the CO₂ refers to CO₂that is in a fluid state while also being above both of its criticalpressure and critical temperature. In such a supercritical state, CO₂may behave as a supercritical fluid, expanding to fill a container likea gas but with a density like that of a liquid. Compressors are used toincrease the CO₂ pressure from near atmospheric pressure to asupercritical phase (i.e., state), in some cases, of upwards ofapproximately 2215 pounds per square inch absolute (PSIA) at upwards ofapproximately 100° F. A more efficient system for compressing thecarbonous gas is disclosed that is capable of using vapor absorptionchiller (VAC) systems to lower the carbonous gas temperatures, resultingin a more efficient and less costly compression of the carbonous gas.Further, liquid compressors (e.g., liquid pumps) may also be used thatuse significantly less power to operate than gas compressors. Indeed, bycombining vapor chiller systems with liquid compressors it may bepossible to substantially reduce the amount of energy expended inreaching a supercritical phase of the carbonous gas, thereby increasingefficiency and reducing cost.

With the foregoing in mind, FIG. 1 depicts an embodiment of an IGCCpower plant 100 that may produce and burn a synthetic gas, i.e., syngas.Elements of the IGCC power plant 100 may include a fuel source 102, suchas a solid feed, that may be utilized as a source of energy for the IGCCpower plant 100. The fuel source 102 may include coal, petroleum coke,biomass, wood-based materials, agricultural wastes, tars, coke oven gasand asphalt, or other carbon containing items.

The solid fuel of the fuel source 102 may be passed to a feedstockpreparation unit 104. The feedstock preparation unit 104 may, forexample, resize or reshape the fuel source 102 by chopping, milling,shredding, pulverizing, briquetting, or palletizing the fuel source 102to generate feedstock. Additionally, water, or other suitable liquidsmay be added to the fuel source 102 in the feedstock preparation unit104 to create slurry feedstock. In certain embodiments, no liquid isadded to the fuel source, thus yielding dry feedstock. The feedstock maybe conveyed into a gasifier 106 for use in gasification operations.

The gasifier 106 may convert the feedstock into a syngas, e.g., acombination of carbon monoxide and hydrogen. This conversion may beaccomplished by subjecting the feedstock to a controlled amount of anymoderator and limited oxygen at elevated pressures (e.g., fromapproximately 600 pounds per square inch gauge (PSIG)-1200 PSIG) andelevated temperatures (e.g., approximately 2200° F.-2700° F.), dependingon the type of feedstock used. The heating of the feedstock during apyrolysis process may generate a solid (e.g., char) and residue gases(e.g., carbon monoxide, hydrogen, and nitrogen).

A combustion process may then occur in the gasifier 106. The combustionmay include introducing oxygen to the char and residue gases. The charand residue gases may react with the oxygen to form carbon dioxide andcarbon monoxide, which provides heat for the subsequent gasificationreactions. The temperatures during the combustion process may range fromapproximately 2200° F. to approximately 2700° F. In addition, steam maybe introduced into the gasifier 106. The gasifier 106 utilizes steam andlimited oxygen to allow some of the feedstock to be burned to producecarbon monoxide and energy, which may drive a second reaction thatconverts further feedstock to hydrogen and additional carbon dioxide.

In this way, a resultant gas is manufactured by the gasifier 106. Thisresultant gas may include approximately 85% of carbon monoxide andhydrogen in equal proportions, as well as CH₄, HCl, HF, COS, NH₃, HCN,and H₂S (based on the sulfur content of the feedstock). This resultantgas may be termed untreated syngas, since it contains, for example, H₂S.The gasifier 106 may also generate waste, such as slag 108, which may bea wet ash material. This slag 108 may be removed from the gasifier 106and disposed of, for example, as road base or as another buildingmaterial. To treat the untreated syngas, a gas treatment unit 110 may beutilized. In one embodiment, the gas treatment unit 110 may be a watergas shift reactor. The gas treatment unit 110 may scrub the untreatedsyngas to remove the HCl, HF, COS, HCN, and H₂S from the untreatedsyngas, which may include separation of sulfur 111 in a sulfur processor112 by, for example, an acid gas removal process in the sulfur processor112. Furthermore, the gas treatment unit 110 may separate salts 113 fromthe untreated syngas via a water treatment unit 114 that may utilizewater purification techniques to generate usable salts 113 from theuntreated syngas. Subsequently, the gas from the gas treatment unit 110may include treated syngas, (e.g., the sulfur 111 has been removed fromthe syngas), with trace amounts of other chemicals, e.g., NH₃ (ammonia)and CH₄ (methane). A gas processor 115 may be used to remove additionalresidual gas components 116, such as ammonia and methane, as well asmethanol or any residual chemicals from the treated syngas. However,removal of residual gas components from the treated syngas is optional,since the treated syngas may be utilized as a fuel even when containingthe residual gas components, e.g., tail gas.

In some embodiments, a carbon capture system 117 may extract and processthe carbonous gas (e.g., CO₂ that is approximately 60-80 percent,approximately 80-100 percent or approximately 90-100 percent pure byvolume) from the syngas (i.e., pre-combustion extraction). Additionally,the carbon capture system 117 may extract and process the carbonous gasafter combustion (i.e., post-combustion extraction), for example, byextracting the CO₂ from a flue gas. An extracted CO₂ may then betransferred into a gas compression system 118. In certain embodiments,the gas compression system 118 may compress, dehydrate, and liquefy theextracted CO₂, resulting in a CO₂ that is more easily transported andstored. The CO₂ may then be redirected into a carbon sequestrationsystem 119, and/or an EOR pipeline 120 for use in, for example, oilrecovery activities. Accordingly, emissions of the extracted CO₂ intothe atmosphere may be reduced or eliminated by redirecting the extractedCO₂ for use in such activities.

Gas compression activities may be able to more efficiently compress theextracted CO₂ by cooling the compressed CO₂ to lower temperatures.Accordingly, a VAC system 122 may operate to transmit water to cool thecompression system 118 during operation. The VAC system 122 may alsooperate to retrieve water made hot through absorption of heat generatedby the compression system 118 while compressing. The VAC system 122 mayfurther cycle the water used in conjunction with the compression system118 through a cooling tower 124 that may act as a water reservoir. Bycooling the compression system 118 via the VAC system 122 utilizing thecooling tower 124, the CO₂ in the compression system 118 may becompressed more easily, that is, use less energy to compress the CO₂,and, thus, the efficiency of the compression system 118 may beincreased. Furthermore, the use of the VAC system 122 may be beneficialbecause of its ability to reuse heat that might otherwise be wasted.

Continuing with the syngas processing, once the CO₂ has been capturedfrom the syngas, the treated syngas may be then transmitted to acombustor 125, e.g., a combustion chamber, of a gas turbine engine 126as combustible fuel. The IGCC power plant 100 may further include an airseparation unit (ASU) 128. The ASU 128 may operate to separate air intocomponent gases by, for example, distillation techniques. The ASU 128may separate oxygen from the air supplied to it from a supplemental aircompressor 129, and the ASU 128 may transfer the separated oxygen to thegasifier 106. Additionally the ASU 128 may transmit separated nitrogento a diluent nitrogen (DGAN) compressor 130.

The DGAN compressor 130 may compress the nitrogen received from the ASU128 at least to pressure levels equal to those in the combustor 125, soas not to interfere with the proper combustion of the syngas. Thus, oncethe DGAN compressor 130 has adequately compressed the nitrogen to aproper level, the DGAN compressor 130 may transmit the compressednitrogen to the combustor 125 of the gas turbine engine 126. Thenitrogen may be used as a diluent to facilitate control of emissions,for example.

As described previously, the compressed nitrogen may be transmitted fromthe DGAN compressor 130 to the combustor 125 of the gas turbine engine126. The gas turbine engine 126 may include a turbine 132, a drive shaft133 and a compressor 134, as well as the combustor 125. The combustor125 may receive fuel, such as syngas, which may be injected underpressure from fuel nozzles. This fuel may be mixed with compressed airas well as compressed nitrogen from the DGAN compressor 130, andcombusted within combustor 125. This combustion may create hotpressurized exhaust gases.

The combustor 125 may direct the exhaust gases towards an exhaust outletof the turbine 132. As the exhaust gases from the combustor 125 passthrough the turbine 132, the exhaust gases force turbine blades in theturbine 132 to rotate the drive shaft 133 along an axis of the gasturbine engine 126. As illustrated, the drive shaft 133 is connected tovarious components of the gas turbine engine 126, including thecompressor 134.

The drive shaft 133 may connect the turbine 132 to the compressor 134 toform a rotor. The compressor 134 may include blades coupled to the driveshaft 133. Thus, rotation of turbine blades in the turbine 132 may causethe drive shaft 133 connecting the turbine 132 to the compressor 134 torotate blades within the compressor 134. This rotation of blades in thecompressor 134 causes the compressor 134 to compress air received via anair intake in the compressor 134. The compressed air may then be fed tothe combustor 125 and mixed with fuel and compressed nitrogen to allowfor higher efficiency combustion. Drive shaft 133 may also be connectedto a load 136, which may be a stationary load, such as an electricalgenerator for producing electrical power, for example, in a power plant.Indeed, the load 136 may be any suitable device that is powered by therotational output of the gas turbine engine 126.

The IGCC power plant 100 also may include a steam turbine engine 138 anda heat recovery steam generation (HRSG) system 139. The steam turbineengine 138 may drive a second load 140. The second load 140 may also bean electrical generator for generating electrical power. However, boththe first and second loads 136, 140 may be other types of loads capableof being driven by the gas turbine engine 126 and steam turbine engine138. In addition, although the gas turbine engine 126 and steam turbineengine 138 may drive separate loads 136 and 140, as shown in theillustrated embodiment, the gas turbine engine 126 and steam turbineengine 138 may also be utilized in tandem to drive a single load via asingle shaft. The specific configuration of the steam turbine engine138, as well as the gas turbine engine 126, may beimplementation-specific and may include any combination of sections.

The system 100 may also include the HRSG 139. Heated exhaust gas fromthe gas turbine engine 126 may be transported into the HRSG 139 and usedto heat water and produce steam used to power the steam turbine engine138. Exhaust from, for example, a low-pressure section of the steamturbine engine 138 may be directed into a condenser 142. The condenser142 may utilize the cooling tower 124 to exchange heated water forchilled water. The cooling tower 124 acts to provide cool water to thecondenser 142 to aid in condensing the steam transmitted to thecondenser 142 from the steam turbine engine 138. Condensate from thecondenser 142 may, in turn, be directed into the HRSG 139. Again,exhaust from the gas turbine engine 126 may also be directed into theHRSG 139 to heat the water from the condenser 142 and produce steam.

In combined cycle power plants such as IGCC power plant 100, hot exhaustmay flow from the gas turbine engine 126 and pass to the HRSG 139, whereit may be used to generate high-pressure, high-temperature steam. Thesteam produced by the HRSG 139 may then be passed through the steamturbine engine 138 for power generation. In addition, the produced steammay also be supplied to any other processes where steam may be used,such as to the gasifier 106. The gas turbine engine 126 generation cycleis often referred to as the “topping cycle,” whereas the steam turbineengine 126 generation cycle is often referred to as the “bottomingcycle.” By combining these two cycles as illustrated in FIG. 1, the IGCCpower plant 100 may lead to greater efficiencies in both cycles. Inparticular, exhaust heat from the topping cycle may be captured and usedto generate steam for use in the bottoming cycle.

FIG. 2 illustrates the compression system 118 in conjunction with theVAC system 122 of the IGCC system 100. As illustrated, compressionsystem 118 may be a multi-stage compression system 118. That is, thecompression system 118 may include a first stage compressor 144, asecond stage compressor 146, and a liquid pump 148. The compressors 144and 146 may operate in conjunction (e.g., in series) with the liquidpump 148 to compress the CO₂ received from the CO₂ extraction system(e.g., pre-combustion or post-combustion extraction) to a level thatfacilitates transmission to the CO₂ sequestration system 119 and/or EORpipeline 120. The VAC system 122 is capable of using the chilled water155 to liquefy the CO₂ at intermediate pressures and then use the liquidpump 148 to raise the liquid CO₂ to a super critical pressure. Such amethod is a more efficient way of liquefying CO₂ than, for example, whenthe chilled water 155 is not used. Because of the irreversibility duringcompression, the exit temperature of the CO₂ after compressionincreases. To reduce this temperature increase, inter-cooling betweenthe stages of compression and/or the liquid pump may be desirable.Indeed, by using VAC inter-cooling as detailed below, it may be possibleto more efficiently compress and liquefy the CO₂.

The compression system 118 may include an intermediate chilled waterheat exchanger 152, and a final chilled water heat exchanger 154 thatmay receive a coolant through a chilled temperature coolant path 155.The compression system 118 may also include an intermediate heated waterheat exchanger 156, and a final heated water heat exchanger 158 that mayreceive a coolant through a heated temperature coolant path 159.Collectively, the chilled water heat exchangers 152, 154 and the heatedwater heat exchangers 156, 158 may be utilized to reduce the temperatureof the CO₂ flowing through a gas path 163 of the compression system 118.It should be noted that instead of water, other suitable liquids may beutilized in conjunction with the heat exchangers 152, 154, 156, 158 as acoolant. An example of the operation of the heat exchangers 152, 154,156, 158 in conjunction with the compressors 144, 146 and the liquidpump 148 will be discussed below.

A CO₂ flow from, for example, the carbon capture system 117 may beredirected to the first stage compressor 144. The CO₂ flow may be at aninlet pressure of approximately 15 PSIA to 40 PSIA and a temperature ofbetween approximately 80° F.-120° F. The first stage compressor 144 maycompress the CO₂ to a pressure of approximately 200 PSIA-400 PSIA and atemperature of approximately between 400° F. to 600° F. To aid inreducing the temperature of the CO₂, so that the second stage compressor146 may expend less energy in compressing the CO₂, the CO₂ may passthrough the intermediate heated water heat exchanger 156.

The intermediate heated water heat exchanger 156 may receive heatedwater from a generator 164, e.g. a heat exchanger, of the VAC system122. The water may be at a temperature of approximately 90° F.-200° F.The heated water may pass through the intermediate heated water heatexchanger 156, through a conduit (e.g., coolant path 159), such as atube. This coolant path 159 may contact the CO₂ as it passes through theintermediate heated water heat exchanger 156, thus reducing thetemperature of the CO₂ from, for example, approximately 400° F.-600° F.,to approximately 100° F.-to 300° F., while increasing the temperature ofthe heated water to, for example, approximately 150° F.-250° F.Subsequent to passing through the intermediate heated water heatexchanger 156, the CO₂ may be passed to the intermediate chilled waterheat exchanger 152, so as to come into contact with a conduit (e.g.,coolant path 155), containing chilled water. The chilled water may betransmitted from an evaporator 160 of the VAC system 122 via a pump 162to the final chilled water heat exchanger 154 and then subsequently tothe intermediate chilled water heat exchanger 152. The CO₂ may contactthe conduit carrying the chilled water as it passes through theintermediate chilled water heat exchanger 152, thus reducing thetemperature of the CO₂, for example, to approximately 60° F.-100° F.,while increasing the temperature of the chilled water to approximately50° F.-80° F.

The CO₂ may then pass to the second stage compressor 146. The CO₂entering the second stage compressor 146 may be at a temperature ofapproximately 60° F.-100° F. and at a pressure of approximately 200PSIA-400 PSIA. The second stage compressor 146 may compress the CO₂ toapproximately 550 PSIA-950 PSIA. However, in compressing the CO₂, thetemperature of the CO₂ may also increase from, for example,approximately 60° F.-100° F. to approximately 150° F.-350° F. Again, toaid in reducing the temperature of the CO₂ such that it may be condensedor liquefied at a more reduced pressure, and so that the liquid pump 148may expend less energy for raising the liquid CO₂ to supercriticalstage, the CO₂ may pass through the final heated water heat exchanger158.

The final heated water heat exchanger 158 may receive heated water fromthe intermediate heated water heat exchanger 156. The water may be at atemperature of approximately 90° F.-250° F. The heated water may passthrough the final heated water heat exchanger 158, through a conduit,such as a tube. This conduit may contact the CO₂ as it passes throughthe final heated water heat exchanger 158, thus reducing the temperatureof the CO₂ from, for example, approximately 150° F.-350° F. toapproximately 100° F.-300° F., while increasing the temperature of theheated water. The heated water may then be transmitted to the generator164 of the VAC system 122 via a pump 166. Subsequent to passing throughthe final heated water heat exchanger 158, the CO₂ may be passed to thefinal chilled water heat exchanger 154, so as to come into contact witha conduit containing chilled water. Chilled water may be transmittedfrom the evaporator 160 of the VAC system 122 via the pump 162 to thefinal chilled water heat exchanger 154. The chilled water may be, forexample, at approximately 20° F.-50° F. The chilled water may passthrough the final chilled water heat exchanger 154, through a conduit,such as a tube. The CO₂ may contact the conduit carrying the chilledwater as it passes through the final chilled water heat exchanger 154,thus reducing the temperature of the CO₂ from, for example,approximately 100° F.-300° F. to approximately 25° F.-75° F., whileincreasing the temperature of the chilled water from approximately 20°F.-50° F. to approximately 40° F.-70° F. Indeed, the temperature of theCO₂ in the gas path 163 after the chilled water heat exchanger 154 maybe set such that all gaseous CO₂ becomes condensed or liquefied.

The liquefied CO₂ may then pass to the liquid pump 148. The CO₂ enteringthe liquid pump 148 may be at a temperature of approximately 25° F.-75°F. and at a pressure of approximately 550 PSIA-950 PSIA. The liquid pump148 may further compress the CO₂ to super critical pressure.Accordingly, CO₂ exiting the liquid pump 148 may be at a pressure ofupwards of approximately 2215 PSIA at a temperature of upwards ofapproximately 60° F. At this pressure, the compressed CO₂ may beintroduced into, for example the carbon sequestration system 119 and/orthe EOR pipeline 120. The flow of chilled and warm water through thecompression system 118 above may be supplied by the VAC system 122,increasing compression and liquefaction efficiency. Accordingly, FIG. 3illustrates the operation of a VAC system 122.

FIG. 3 illustrates an embodiment of VAC system 122. Heat from, forexample, the heat exchangers 156 and 158 of FIG. 2, may operate as wasteheat sources to provide hot water or steam that may be used to power theVAC system 122. The use of waste heat is advantageous because heat thatmay have otherwise have been wasted or cast off is used to aid incompression activities. Accordingly, the VAC system 122 may include anevaporator 160, a generator 164, an absorber 168, and a condenser 170.The evaporator 160 may be kept at low pressure, for example, at apressure approximately near a vacuum. The low-pressure of the evaporator160 may cause a refrigerant, such as NH₃ (ammonia), to boil at very lowtemperatures. As illustrated, the evaporator 160 includes a heatexchanger 161 to exchange heat with the compression system 118 via heatexchangers 152 and 154. In particular, heat exchangers 152 and 154remove heat from the compression system 118, and the heat exchanger 161adds heat to the evaporator 160. The evaporator 160 may also take heatfrom the surroundings of the evaporator 160. Because of this heattransfer, the refrigerant may be converted into vapor which may flowinto the absorber 168. The absorber 168 may combine the refrigerantvapor with water. In addition, the absorber 168 cools and condenses therefrigerant vapor and water via a heat exchanger 169 that circulates acoolant (e.g., water) with cooling tower 124. The water, rich withrefrigerant, may then be pumped via an absorbent pump 172 to thegenerator 164.

In the generator 164, heat may be transferred to the refrigerant richliquid by an external heat source, such as hot water or steam from thecompression system 118 (e.g., heat exchangers 156 and 158). Inparticular, the generator 164 has a heat exchanger 165 to receive heatfrom the heat exchangers 156 and 158 in the compression system 118. Theheat from the hot water or steam may boil the refrigerant off from therefrigerant rich liquid. The hot and refrigerant lean liquid then mayreturn back to the absorber 168, where heat may be removed by coolingwater flow from cooling tower 124. The refrigerant vapor from thegenerator 164 may be transmitted to the condenser 170, where therefrigerant vapor may be converted into liquid by exchanging heat withcooling water from the cooling tower 124. In particular, the condenser170 has a heat exchanger 171 to remove heat via circulation of waterwith the cooling tower 124. The cooled refrigerant may then returned tothe low-pressure evaporator 160, where it takes heat from the water fromthe compression system 118, thus completing a VAC thermodynamic cycle.The VAC thermodynamic cycle may be able to capture heat from thecompression activities and reuse the heat to create a chilling effect tocool the CO₂ flow, thus more efficiently compressing the CO₂.

FIG. 4 illustrates an embodiment of an N-stage compression system 118 inconjunction with the VAC system 122 of the IGCC system 100. Asillustrated, the compression system 118 may be a multi-stage compressionsystem 118. That is, the compression system 118 may include a firststage compressor 144, a final stage compressor 148, and multipleintermediate stages (e.g., 2, 3, 4, 5, 6, 7, 8, 9, 10, or more) eachstage including a compressor 146. These compressors 144, 146, 148 mayoperate in conjunction (e.g., in series) with the liquid pump 148 tocompress and liquefy the CO₂ received from the carbon capture system 117to a level that is easily transported and stored. The compression system118 may include an inlet chilled water heat exchanger 174, a finalchilled water heat exchanger 154, and multiple intermediate chilledwater heat exchangers 152, for example, one or more per each of themultiple intermediate stages including an intermediate compressor 146.The chilled water heat exchangers 152, 154, 174 may receive a coolantthrough the chilled temperature coolant path 155. Collectively, thechilled water heat exchangers 152, 154, 174 and the heated water heatexchangers 156, 158 may be utilized to reduce the temperature of the CO₂flowing through the gas path 163 of the compression system 118. Thecompression system 118 may also include a final heated water heatexchanger 158 and multiple intermediate heated water heat exchangers156, one or more per each of the multiple intermediate stages includingan intermediate compressor 146, as described below. The heated waterheat exchangers 152, 154, 174 may receive a coolant through the heatedtemperature coolant path 159.

Chilled water may be transmitted from the evaporator 160 of the VACsystem 122 via the pump 162 to the inlet chilled water heat exchanger174. The chilled water may pass through the inlet chilled water heatexchanger 174, through a conduit (e.g., coolant path 155), such as atube. This conduit may contact the CO₂ as it passes through the inletchilled water heat exchanger 174, thus reducing the temperature of theCO₂ while increasing the temperature of the chilled water. The CO₂ maythen pass to the first stage compressor 144. The first stage compressor144 may compress the CO₂. However, in compressing the CO₂, thetemperature of the CO₂ may also increase. To aid in reducing thetemperature of the CO₂, so that the intermediate compressor 146 mayexpend less energy in compressing the CO₂, the CO₂ may pass through theintermediate heated water heat exchanger 156.

The intermediate heated water heat exchanger 156 may receive heatedwater from the generator 164, e.g. a heat exchanger, of the VAC system122. The heated water may pass through the intermediate heated waterheat exchanger 156, through a conduit, such as a tube. This conduit maycontact the CO₂ as it passes through the intermediate heated water heatexchanger 156, thus reducing the temperature of the CO₂ while increasingthe temperature of the heated water. The temperate of the CO₂ is reducedbecause the heated water may be cooler than the CO₂. Subsequent topassing through the intermediate heated water heat exchanger 156, theCO₂ may be passed to the intermediate chilled water heat exchanger 152,so as to come into contact with a conduit containing chilled water. TheCO₂ may contact the conduit carrying the chilled water as it passesthrough the intermediate chilled water heat exchanger 152, thus reducingthe temperature of the CO₂ while increasing the temperature of thechilled water.

The CO₂ may then pass to the intermediate compressor 146. Theintermediate compressor 146 may compress the CO₂. However, incompressing the CO₂, the temperature of the CO₂ may also increase. Toaid in reducing the temperature of the CO₂, so that the next compressorstage may expend less energy in compressing the CO₂, the CO₂ may passthrough a final heated water heat exchanger 158. The final heated waterheat exchanger 158 may receive heated water from the intermediate heatedwater heat exchanger 156. The heated water may pass through the finalheated water heat exchanger 158, through a conduit, such as a tube. Thisconduit may contact the CO₂ as it passes through the final heated waterheat exchanger 158, thus reducing the temperature of the CO₂, whileincreasing the temperature of the heated water. The heated water maythen be transmitted to the generator 164 of the VAC system 122 via apump 166. Subsequent to passing through the final heated water heatexchanger 158, the CO₂ may be passed to the final chilled water heatexchanger 154, so as to come into contact with a conduit containingchilled water. The CO₂ may contact the conduit carrying the chilledwater as it passes through the final chilled water heat exchanger 154,thus reducing the temperature of the CO₂, while increasing thetemperature of the chilled water. The CO₂ may then pass to the liquidpump 148. The liquid pump 148 may compress the CO₂ to super criticalstate. Consequently, the liquefied CO₂ may be more easily transportedand stored, through, for example, the use of liquid pumps and liquidconduits.

Collectively, the chilled water heat exchangers 152, 154, 174 and theheated water heat exchangers 156, 158 may be utilized to reduce thetemperature of the CO₂ flowing through the compression system 118. Inthis manner, each stage of a N-stage compression system 118 may includecorresponding heat exchangers designed to cool the CO₂ gas flowingthrough the various compressors corresponding to a given compressionstage.

Technical effects of the invention include the ability to capture andemploy waste heat to efficiently compress a carbonous gas, e.g., CO₂.Vapor absorption chiller (VAC) systems may be utilized to reclaim heatgenerated during compression activities. The reclaimed heat may befurther utilized to drive a thermodynamic cycle that can result incooling of the CO₂ flow at a reduced pressure such that it becomesliquid, thus allowing for enhanced efficiencies of CO₂ compression inreaching the super-critical state. Indeed, by combining vapor chillersystems with liquid compressors it may be possible to substantiallyreduce the amount of energy expended in reaching a liquid phase of thecarbonous gas, increasing efficiency and reducing cost. The liquefiedCO₂ may be more efficiently transported and stored. Accordingly, moreefficient and less costly liquid conduits and liquid pumps may be usedto transport the CO₂ for storage and use, for example, in oil recoveryactivities.

This written description uses examples to disclose the invention,including the best mode, and also to enable any person skilled in theart to practice the invention, including making and using any devices orsystems and performing any incorporated methods. The patentable scope ofthe invention is defined by the claims, and may include other examplesthat occur to those skilled in the art. Such other examples are intendedto be within the scope of the claims if they have structural elementsthat do not differ from the literal language of the claims, or if theyinclude equivalent structural elements with insubstantial differencesfrom the literal languages of the claims.

1. A system, comprising: a carbonous gas compression system comprising acompressor configured to compress the carbonous gas; and a vaporabsorption chiller (VAC) configured to circulate a coolant through atleast one coolant path through the carbonous gas compression system. 2.The system of claim 1, wherein the carbonous gas comprises carbondioxide that is at least approximately 60 percent pure by volume.
 3. Thesystem of claim 1, wherein the carbonous gas compression systemcomprises a heat exchanger in a gas path upstream of the compressor, andthe at least one coolant path of the VAC extends through the heatexchanger.
 4. The system of claim 3, wherein the heat exchanger upstreamof the compressor comprises a heated water heat exchanger.
 5. The systemof claim 3, wherein the heat exchanger upstream of the compressorcomprises a chilled water heat exchanger.
 6. The system of claim 1,wherein the carbonous gas compression system comprises a chilled waterheat exchanger and a heated water heat exchanger in a gas path upstreamof the compressor, and the at least one coolant path of the VACcomprises a chilled temperature coolant path extending through the firstchilled water heat exchanger and a heated temperature coolant pathextending through the heated water heat exchanger.
 7. The system ofclaim 1, wherein the carbonous gas compression system comprises a firstchilled water heat exchanger in a gas path downstream of the compressor,a second chilled water heat exchanger and a heated water heat exchangerin the gas path upstream of the compressor, and the at least one coolantpath of the VAC comprises a chilled temperature coolant path extendingthrough the first chilled water heat exchanger and through the secondchilled water heat exchanger, and a heated temperature coolant pathextending through the heated water heat exchanger.
 8. The system ofclaim 1, wherein the carbonous gas compression system is configured toliquefy the carbonous gas.
 9. The system of claim 8, wherein thecarbonous gas compression system comprises a liquid pump configured toraise the pressure of the liquefied carbonous gas to a super criticalpressure.
 10. The system of claim 8, wherein the carbonous gascompression system comprises a plurality of compression stages withrespective compressors, the carbonous gas compression system comprises aheat exchanger in a gas path between the plurality of compression stagesand the liquid pump, and wherein the at least one coolant path extendsthrough the heat exchanger.
 11. The system of claim 1, wherein the VACcomprises an evaporator configured to boil a refrigerant, an absorberconfigured to generate a refrigerant vapor from the refrigerant, agenerator configured to transfer heat to the refrigerant vapor, and acondenser configured to liquefy the refrigerant vapor.
 12. A system,comprising: a carbonous gas capture system configured to extract acarbonous gas; a carbonous gas compression system comprising acompressor configured to receive the carbonous gas from the carbonousgas capture system and to compress and liquefy the carbonous gas; avapor absorption chiller (VAC) configured to circulate a coolant throughat least one coolant path through the carbonous gas compression system;and a carbon sequestration system or an enhanced oil recovery (EOR)pipeline configured to receive the carbonous gas compressed andliquefied by the carbonous gas compression system.
 13. The system ofclaim 12, wherein the carbonous gas comprises carbon dioxide that is atleast approximately 60 percent pure by volume.
 14. The system of claim12, wherein the carbonous gas compression system comprises a heatexchanger in a gas path upstream of the compressor, and the at least onecoolant path of the VAC extends through the heat exchanger.
 15. Thesystem of claim 12, wherein the carbonous gas compression systemcomprises a heat exchanger in a gas path downstream of the compressor,and the coolant path extends through the heat exchanger.
 16. The systemof claim 12, comprising a liquid pump configured to raise the pressureof the liquefied carbonous gas compressed by the carbonous gascompression system to a supercritical pressure, wherein the carbonousgas compression system comprises a plurality of compression stages withrespective compressors and with at least one heat exchanger in a gaspath between the plurality of compression stages and the liquid pump,and the at least one coolant path extends through the heat exchanger.17. The system of claim 12, wherein the at least one coolant pathcomprises a chilled temperature coolant path extending through a chilledwater heat exchanger in a gas path upstream of the compressor, and aheated temperature coolant path extending through a heated water heatexchanger in the gas path upstream of the compressor.
 18. A system,comprising: a carbon dioxide (CO₂) compression system comprising acompressor configured to compress the CO₂; a vapor absorption chiller(VAC) configured to circulate a coolant through at least one coolantpath through the CO₂ compression system; and a liquid pump configured toraise the pressure of the CO₂.
 19. The system of claim 18, wherein theCO₂ is converted to a supercritical liquid.
 20. The system of claim 18,wherein the CO₂ compression system comprises a heat exchanger in a gaspath upstream of the compressor, and the at least one coolant path ofthe VAC extends through the heat exchanger.